As a result of guidance issued by the Pennsylvania Department of Revenue (“DOR”), solar generators may qualify for the sales and use tax manufacturing exclusion.  Accordingly, solar generators’ purchases of expensive machinery, equipment, parts and foundations, and supplies would be excluded from Pennsylvania’s sales and use tax.

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The DOR issued guidance in Sales Tax Bulletin No. 2010-01 and Sales and Use Tax Ruling No. SUT-10-0001 on tax exclusions for Pennsylvania-based solar generators.  As a result of this guidance, taxpayers constructing solar generation facilities in Pennsylvania could qualify for the state sales and use tax manufacturing exclusion.

Eligibility for the Exclusion:

The guidance suggests that in order to qualify as being “engaged in the business of manufacturing electricity,” the following must apply:

  • The electricity production is conducted in an independent, separate and distinct location, utilizing independent, separate and distinct machinery and supplies devoted predominately to electricity producing activities.
  • The electricity production is the responsibility of employees assigned to the job of electricity production and whose duties are predominately related to electricity production.
  • Separate accounting or interdepartmental billing is provided to reflect the cost of operating electricity production activities and to charge these costs against any other business activities conducted by the electricity producer.
  • The electricity production activities are separate and distinct from any other business activities of the electrical producer.
  • Electrical production activities are of sufficient size, scope and character that they could be conducted on a commercially viable basis separate and distinct from any other business activities of the electricity producer.

Accordingly, if a Pennsylvania solar generator meets all of the criteria listed above, it could claim the manufacturing exclusion from sales and use tax on the purchase of equipment, machinery, parts and foundations therefore, and supplies claimed to be directly used in electricity manufacturing.  The particular generator in the ruling planned to sell the output to the public utility.  It seems generators selling to the wholesale market or entities could also qualify; however, the DOR has not issued a specific guidance on this situation.

Claiming the Exclusion:

A contractor building a Pennsylvania solar generation facility could also claim the manufacturing exclusion on the purchase of equipment, machinery, parts and foundations therefore, and supplies to be installed pursuant to a construction contract.  The contractor would have to execute and tender a properly completed Pennsylvania exemption certificate (Form REV-1220) to the Pennsylvania licensed vendor.  The contractor must also obtain a properly completed Pennsylvania exemption certificate (Form REV-1220) from the person/entity with whom he enters into such construction contract in order to protect himself in case of a Pennsylvania sales and use tax audit.

Recovering Pre-paid Sales and Use Tax on Exempt Purchases:

If a Pennsylvania solar generator or a construction contractor has already paid sales and use tax on purchases that could have been exempt from taxation, they may be able to claim a refund of the tax paid on purchases made in the last three years.

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If you have any questions on whether your facility qualifies for the manufacturing exclusion or whether you may be entitled to sales and use tax refunds, please contact Paul Morcom, or any member of McNees’s tax group, to discuss.

A recent decision by the Pennsylvania Public Utility Commission (“PUC” or “Commission”) confirms that Pennsylvania public utilities with combined sewer systems (i.e., systems that collect both sewage and stormwater) may incorporate stormwater charges in their service charges.  While some public utilities have already been incorporating stormwater collection charges in their sewage rates, not all utilities have carried forth this practice.  As a result, this decision could increase sewage rates for some large commercial and industrial customers experiencing significant stormwater flows.

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On March 30, 2016, the Pennsylvania American Water Company (“PAWC”) and the Sewer Authority of the City of Scranton (“SSA”) filed an Application with the PUC to permit PAWC to purchase the SSA’s combined sewer system.  As indicated above, combined sewer systems collect sewage and stormwater, so the PUC’s disposition of this Application would clarify the ability of a Pennsylvania public utility to include stormwater charges in its wastewater service rates.  Although Administrative Law Judges David A. Salapa and Steven K. Haas recommended that the PUC reject the proposed Application, the PUC approved it on October 19, 2016.

As a result of the PUC’s approval, statutory enabling legislation was required.  Senate Bill No. 881 was revived and amended to make necessary changes to the Public Utility Code.  Specifically, the Bill amends the Public Utility Code to change the reference of “sewer” to “wastewater,” and expanded the definition of wastewater to include certain “stormwater.”  This bill passed both chambers [October 26 (Senate) and October 27 (House)] and was signed by Governor Wolf.

The Bill provides as follows:

Wastewater.  Any used water and water-carried solids collected or conveyed by a sewer, including:

(1)  Sewage, as defined in Section 2 of the act of January 24, 1966 (1965 P.L. 1535, No. 537), known as the Pennsylvania Sewage Facilities Act.

(2)  Industrial waste originating from an establishment.  For the purposes of this paragraph, the terms “industrial waste” and “establishment” shall be as defined in Section 1 of the Act of June 22, 1937 (P.L. 1987, No. 394), known as the Clean Streams Law.

(3)   Infiltration or inflow into sewers.

(4)   Other water containing solids or pollutants.

(5)  Storm water which is or will become mixed with waters described under paragraph (1), (2), (3) or (4) within a combined sewer system.

The term does not include storm water collected in a Municipal Separate Storm Sewer, as that term is defined by 40 CFR 122.26(b)(8) (Relating to storm water discharges (applicable to state NPDES programs, see § 123.25)), that does not flow into a combined sewer system.

This legislation, now codified as PA Act 154, allows Pennsylvania utilities providing wastewater service to include, in certain cases (i.e., combined sewer systems), stormwater charges into rates.  While some Pennsylvania municipal wastewater service providers (e.g., Philadelphia Water Department) have been including stormwater charges in wastewater rates for some time, it will be much more commonplace with PUC-regulated service providers with this new legislation.

On October 6, 2016, the Pennsylvania Public Utility Commission entered a Final Order in the Proceeding to Evaluate the Transition to Corrected Non‑Solar Tier I Calculation Methodology, Docket A-2009-2093383.  The October 6 Final Order evaluated the public comments regarding the Commission’s proposals to address an unanticipated seven percent increase in the non-solar Tier I Alternative Energy Credit (“AEC”) for the 2016 compliance year.  The Commission is charged with using its general powers to carry out, execute, and enforce AEC obligations under the Alternative Energy Portfolio Standards Act of 2004 (“AEPS Act”).  As we explained in a previous blog entry, the Commission had become aware of a recurring error over the past six years regarding the calculation of the non-solar Tier I AEC obligation quarterly adjustment.

In the Final Order, the PUC rejected the solution that would have required electric distribution companies (“EDCs”) to procure the additional needed AECs, transfer those procured credits to all load serving entities, and recover the costs of the procurement through a preexisting non-bypassable surcharge.  The Commission explained that this solution (1) inappropriately shifts the responsibility to acquire and retire AECs from electric generation suppliers to EDCs under the AEPS Act and Commission regulations; (2) is administratively burdensome; (3) incurs unnecessary time and resources; and (4) does not ameliorate the costs for compliance, which would ultimately be borne by all ratepayers.

Based on the high level of support in the comments, the Commission determined that the second solution – delaying the true-up period for the non-solar Tier I adjustment credits — is the most reasonable solution.  Accordingly, the Commission further extended the true-up period for non‑solar Tier I adjustment obligations for the 2016 AEPS compliance year from November 30, 2016 to May 1, 2017.

If you have any questions or concerns regarding the PUC’s Final Order and how it may potentially impact your business, please do not hesitate to contact us.

On September 21, 2016, the Susquehanna River Basin Commission (“SRBC”) published a proposed rule that would expand the scope of its current authority over projects that withdraw and use water in Pennsylvania, Maryland, and New York.  The proposal would amend application requirements and SRBC’s review standards for projects, as well as add an entire subpart to its regulations for registration and reporting of “grandfathered” projects (which previously were not regulated).   Water users should expect additional regulation and scrutiny of all projects that involve withdrawals of surface water or groundwater and/or consumptive uses exceeding SRBC thresholds, whether they are new, existing, or (now) grandfathered projects.

Grandfathered Projects.  The most significant proposal is regulation of “grandfathered” projects, which involve water withdrawals or consumptive uses that began before specified dates in the regulations and did not previously require SRBC approval.  SRBC has estimated that there are some-760 grandfathered projects, many of which are not tracked by SRBC or member states, that account for the same amount of water use as all existing regulated consumptive uses in the Basin.  Therefore, SRBC has proposed a mandatory registration-and-reporting program for grandfathered withdrawals and uses, which includes a one-time registration and periodic reporting of withdrawals and uses, along with associated fees.  As support for this rule, SRBC cited to its responsibility to wisely manage water resources in the Basin and the corresponding need to close this “knowledge gap” by comprehensively tracking water usage.

In attempting to close this gap, SRBC has claimed that the registration requirements will not open the door to review-and-approval requirements for grandfathered projects.  In some respects, the registration requirements may be similar to those imposed by the states.  However, this may be only the first step for additional regulation of grandfathered projects, particularly once SRBC gathers and analyzes the registration data.  Indeed, the proposal potentially opens a floodgate of additional regulation. Failure to register within two years of the effective date would render a grandfathered project subject to SRBC’s review-and-approval authority.  Some key informational requirements for this critical registration include:

  • Identification of metering and monitoring for withdrawals and consumptive uses;
  • Reporting five years of quantity data, or other information that may be used to determine quantities withdrawn or consumptively used;
  • Identification of groundwater levels and elevation monitoring methods for groundwater sources;
  • A description of the processes that involve consumptive uses;
  • A request for specific grandfathered quantities; and
  • Any other information SRBC determines necessary.

Accordingly, it is clear that SRBC intends to scrutinize whether and to what extent currently unregulated withdrawals and uses actually qualify for “grandfathering.”  Under the proposal, the SRBC Executive Director must determine the appropriate grandfathered quantity and, in doing so, can examine the accuracy of metering and monitoring.  Increases of any amount over the determined grandfathered quantity would trigger SRBC’s review-and-approval authority.  Although SRBC’s approach is not yet in final form, those potentially affected should already ensure they are accurately metering and documenting withdrawals and usage.  It will also be important for potentially affected water users to understand their processes and monitor consumptive uses from those processes.  For example, as part of the registration, one provision requires SRBC to evaluate current metering and monitoring and authorizes SRBC to require a metering and monitoring plan.  The proposal would also trigger consumptive-use mitigation, such as fees, for certain grandfathered projects.

Other Projects.  New projects may also be affected by the registration requirements described above because SRBC will use the data on grandfathered projects to analyze the impact on waters of the Basin when deciding to approve or deny a new project.  The proposal also would impose several additional requirements to alter SRBC procedures.  It would amend the required contents of applications for new projects and renewals, requiring specific information depending on the type of project, such as an “alternatives analysis.”  The proposal would amend standards for SRBC’s review and approval and authorize SRBC to require monitoring for impacts to water quality and aquatic biological communities.  SRBC has also proposed to revise the provisions for public hearings and enforcement actions.  For example, the proposal expands the Executive Director’s enforcement authority, allowing the Director to issue compliance orders and determine civil penalty amounts, and acknowledges the SRBC’s use of consent orders and agreements and settlements to resolve enforcement actions.  These are just a few of the various amendments proposed by SRBC that may impact water users.

Next Steps. SRBC intends to hold informational webinars on October 11 and October 17 and then conduct four public hearings throughout November and December, with the first meeting scheduled for November 3 in Harrisburg.  Interested stakeholders should understand how the rules may affect them and weigh in through the public-comment process, which is open until January 30, 2017.  Stakeholders seeking more information or advice should contact attorneys and technical specialists who are experienced in these matters.  McNees contacts include:

 

Recently, many large commercial and industrial enterprises have sought to reduce their operating expenses by shopping for their electric supply.  If you are negotiating an electric supply agreement with an electric supplier, there are a few key terms that you should consider.  Please click here to learn more about the following key negotiable terms: (1) price and product; (2) regulatory changes and other price change opportunities; (3) contract term and renewal; and (4) billing issues.  If you have any further questions, please contact us and we will be happy to assist you.

On August 15, 2016, the Pennsylvania Public Utility Commission (“PUC” or “Commission”) entered a Tentative Order seeking solutions to address an unanticipated 7% increase in the non-solar Tier I Alternative Energy Credit (“AEC”) for the 2016 compliance year.[1]  The Commission is charged with using its general powers to execute and enforce AEC obligations under the Alternative Energy Portfolio Standards Act of 2004 (“AEPS Act”).  A 2008 amendment to the AEPS Act expanded the types of qualifying Tier I resources, including low-impact hydropower and biomass, and required the Commission to increase, at least quarterly, the percentage share of Tier I resources to be sold by electric distribution companies (“EDCs”) and electric generation suppliers.  Recently, the Commission became aware of a recurring error over the past six years regarding the calculation of the non-solar Tier I AEC obligation quarterly adjustment. Correcting the mathematical error for the 2016 compliance year results in the approximate 7%increase in the otherwise anticipated Tier I AEC obligations.  In order to mitigate the impact of the 7% increase, the Commission has proposed two possible solutions.

First, because of the EDCs’ leveraged purchasing power and billing functionality, the Commission proposes requiring EDCs to procure the additional needed AECs through the spot market or a competitive bid process and to then transfer the procured credits to all load serving entities.  EDCs would have the opportunity to recover “the costs of this procurement through a preexisting non‑bypassable charge[2], such as a competitive enhancement rider, solar photovoltaic alternative energy credit rider, or other tariff mechanism as deemed optimal by individual EDCs, so long as the charge is applicable to all rate classes.”[3]  Each EDC would then submit a compliance filing regarding the procurement and cost recovery.

As second solution, the Commission suggests delaying the obligation to settle the adjustment amount associated with the non‑solar Tier I credit obligation for an appropriate time period.   Delaying the adjustment would give entities more time to procure the additional AECs necessary to meet the unanticipated 7% increase.

Aiming to minimize the effect on stakeholders while upholding its duties under the AEPS Act, the Commission seeks public comments on those two proposals, as well as any other proposals to mitigate the impact of the seven percent increase in the non-solar Tier I AEC.  After analyzing the public comments, the PUC will issue its Final Order.

While having the EDC procure the extra credits has appeal because it may be easier to implement, this proposal may result in customers paying for costs that could not or would not be imposed under their contracts with electric generation suppliers.  It also creates a troublesome precedent by relying on a regulatory surcharge to “save” electric generation suppliers from an obligation and risk that is placed on them by Pennsylvania’s restructuring statute.   As an alternative solution, large commercial and industrial customers have suggested to delay the effectiveness of the increased AEPS obligation until the current reporting year, rather than having it apply to a year that was completed prior to the PUC’s announcement.

If you have any questions or concerns regarding this PUC proceeding and how it may potentially impact your business, please do not hesitate to contact us.

[1] The 2016 AEPS compliance year ran from June 1, 2015 through May 31, 2016.  In response to stakeholder concerns, the PUC extended the true-up period from September 1, 2016 to November 1, 2016. The extended true-up period only applies to non-solar Tier I obligation, not to solar Tier I or Tier II obligations.

[2] Non-bypassable charges are assessed on all customers accessing the electric utility’s distribution network, even those customers who shop for electric supply and are taking electric generation supply service from a supplier other than the default supplier (i.e., the electric utility).

[3] See Proceeding to Evaluate Transition to Corrected Non‑Solar Tier I Calculation Methodology, Docket No. M-2009-2093383, at p. 5 (Tentative Order entered Aug. 15, 2016).

As we transition from the dog days of summer and prepare for changes that are guaranteed to come this fall in our state and national political landscapes, we at McNees are considering what the upcoming elections and legislative sessions in Pennsylvania and Washington D.C. mean for our clients.  As discussed this summer, the Pennsylvania budget that became law on July 13 2016, provided relief for those who use state funding and its programs. The Pennsylvania General Assembly and Governor initially faced  a $1.3 billion shortfall in revenues when working on the FY 16-17 budget.  However, the final budget package was $1.2 billion less in spending than what Governor Wolf initially proposed and 5% higher than last year’s budget.  There are a number of new revenue sources for FY 16-17 including a $1 per pack tax increase on cigarettes with new taxes on e-cigarettes and smokeless tobacco products; expansion of the sales and use tax on digital downloads of videos, books, etc.; expansion of the income tax to include state lottery winnings, and a bank shares tax increase. While there was no across the board tax increases such as sales or income taxes or a tax on energy, it is expected and very likely that such tax increases will be necessary in the next budget cycle and is something we advise our large energy consumer clients to be mindful of as we approach this fall when elections and upcoming budget discussions will be front and center.

In addition to those relieved that a budget was passed somewhat timely in early July, there was also a sigh of relief for those who benefit from Senate Bill (SB) 1195 (Act 57 of 2016)  that was signed into law on June 23, 2016 and amends the Pennsylvania Greenhouse Gas Regulation Implementation Act by imposing requirements on Pennsylvania state government regarding its submission of a Clean Power Plan (CPP) to the EPA.  The CCP is intended to regulate states’ carbon emissions from existing electric power plants.

Act 57 reflects a compromise between the Pennsylvania General Assembly and Governor Wolf that allows the General Assembly the opportunity to review and approve the state’s proposed CPP before it is submitted to the EPA.  If either chamber of the General Assembly disapproves the draft CPP, the Department of Environmental Protection (DEP) must review and consider the reasons for disapproval and modify the draft CPP.  At that time, the DEP must resubmit a CPP to the General Assembly and open a public comment period for no less than 180 calendar days on the modified CPP during which time the department shall conduct at least four public hearings in geographically dispersed areas of the Commonwealth.  The Act also includes other provisions that address a default approval or a situation where neither chamber approves the draft or resubmitted modified CPP.  The amendment language further restricts the administration from submitting a CPP to the EPA until after the expiration of the stay issued by the United States Supreme Court on February 9, 2016.

While no one can truly predict how the U.S. Supreme Court will rule, Hillary Clinton’s campaign has boldly made its prediction. Recently during a panel discussion hosted during the Democratic National Convention in Philadelphia at the end of July 2016, Hillary Clinton’s campaign and energy adviser expressed the campaign’s expectation that the U.S. Supreme Court will uphold the CPP and the EPA’s authority to regulate greenhouse gases under the Clean Air Act.  While Donald Trump has not predicted the high court’s position, he has made clear that he is against the CPP and would work to repeal it regardless of the high court’s ruling.  Meanwhile, in Pennsylvania, the republican majority dominated General Assembly will be closely monitoring when the U.S. Supreme Court rules and monitor the state’s plan if and when it is submitted to the EPA.  Until then, the political landscape and issues being debated by the presidential candidates are indicators that this Fall will be quite interesting in many respects with the status and future of the CPP being just one of them.

At McNees, our energy attorneys and government relations professionals will be closely monitoring the politics that will affect this and many subjects of interest to our clients.  Please let us know if there is a specific issue or piece of legislation or subject you have interest in learning more about and we will help you.  Please contact Pam Polacek or Kathy Bruder at 232-8000 should you have any questions or want to discuss.

On June 10, 2016, the IRS released Notice 2016-36, which updates and expands the safe harbor provisions for payments and transfers of property to regulated public utilities occurring after June 20, 2016.  Although the utility must pay taxes on most payments or other contributions that a customer or project developer may make to upgrade the utility’s equipment for new services or generator interconnection, the IRS is exempting projects that it classifies as facilitating the transmission of electricity over the utility’s transmission system.  Specifically, the IRS considers contributions by Qualifying Facilities, wind generators, solar generators and energy storage to be such projects.  As of June 20, 2016, payments or transfers of those types of projects will be treated as a contribution to the capital of a corporation and not a taxable contribution in aid of construction (a “CIAC”). The Notice modifies and supersedes Notice 88-129, 1998 C.B. 541; Notice 90-60, 1990-2 C.B. 345; and Notice 2001-82, 2001-2 C.B. 619 (the “Prior Notices”).

By way of brief background, § 61(a) the Internal Revenue Code (the “Code”) provides that gross income means all income from whatever source derived, unless excluded by law. Section 118(a) of the Code provides that in the case of a corporation, gross income does not include any contribution to the capital of the taxpayer. Section 118(b) of the Code provides that for purposes of § 118(a), the term “contribution to the capital of a taxpayer” does not include any CIAC or any other contribution as a customer or potential customer.

The Prior Notices provided guidance with respect to the treatment of payments and transfers of property to regulated public utilities by qualifying small power producers and qualifying cogenerators (collectively, “Qualifying Facilities”). Specifically, the Prior Notices provided that a payment or transfer of property by a Qualifying Facility to a utility, with which it has a long-term power purchase contract or long-term interconnection agreement, would not constitute a taxable CIAC under either of the following safe harbor provisions: (i) the payment or transfer of property was made exclusively to promote the sale of electricity by the Qualifying Facility to the utility; or (ii) in the event the payment or transfer of property was not made exclusively to promote the sale of electricity by the Qualifying Facility to the utility, such as in the case of a “dual-use intertie,” then provided that the payment or transfer of property satisfied the “5% test.” The 5% test was satisfied if it was reasonably projected that during the ten taxable years of the utility beginning with the taxable year in which the transferred intertie was placed in service, no more than 5% of the projected total power flows over the intertie would flow to the Qualifying Facility.

The IRS issued Notice 2016-36 after recognizing that since the issuance of the Prior Notices, “electricity transmission and distribution systems have evolved and become interlinked so that close coordination of operations with the major U.S. power grids is needed to maintain the various interlinked components.” In order to appropriately adjust tax policy to reflect these industry changes, Notice 2016-36 modifies and supersedes the Prior Notices by (i) consolidating the safe harbor provisions of the Prior Notices, and (ii) providing new safe harbor provisions that remove the requirement that the Qualifying Facility have a long-term power purchase contract or long-term interconnection agreement with the utility. The IRS recognized that due to the substantial interlinking of the electricity distribution systems in the United States, a Qualifying Facility in one region and a utility in a different region that owns a transmission system that will be affected by power delivered by the Qualifying Facility may enter into an agreement in which the utility constructs upgrades to its transmission system, allowing it to handle increased capacity caused by the Qualifying Facility, and the Qualifying Facility may reimburse the utility for the costs of the upgrades. Although these entities may not have reason to enter into a power purchase contract or long-term interconnection agreement, the payment or transfer of property from the Qualifying Facility to the utility will promote reliability and economic efficiency throughout the grid and therefore may be warranted. Prior to the issuance of Notice 2016-36, however, such payment or transfer of property would have constituted a taxable CIAC under § 118(b) of the Code.

The IRS also took notice of the increased importance of renewable energy sources and their impact on the transmission and distribution of power throughout the United States. As a result, Notice 2016-36 also extends the provisions of the safe harbor to payments and transfers of property from solar and wind generators as well as energy storage facilities.

The updated safe harbor provisions are a welcome change and reflect new marketplace realities. If you have questions about Notice 2016-36 or the updated safe harbor provisions, please contact us.

By: Andrew S. Rusniak, Esq.

For many commercial and industrial companies, energy costs comprise a significant portion of their operating expenses.  Although many companies rely on their engineering, facilities management, and procurement departments to implement energy efficient strategies to reduce these costs, legal teams can also play an important role in ensuring that companies are making the most of every opportunity to reduce energy expenses.   For more information on how legal counsel can help companies create smart energy-management strategies, please click here for an in-depth report by Pamela Polacek, a Member of McNees Wallace and Nurick’s Energy and Environmental Group.

Each month, electric bills arrive like clockwork.  For large commercial and industrial businesses, especially those that are energy-intensive, these electric bills can represent a sizeable portion of a business’s monthly expenses.   Given the broad revenue collection ability of regulated utilities, businesses continue to see their electric bills increase to fund things beyond just the supply and delivery of electricity.  Compliance costs associated with things like energy efficiency and renewable energy mandates, economic development, payment assistance programs, and many more programs are often baked into the “price” of electricity that appears on a business’s electric bill.  Such is the case for businesses in Ohio and Pennsylvania.

Given the pressure on large energy-intensive businesses to not only manage the true cost of the supply and delivery of the electricity they consume but also to fund these additional programs through their electric bills, large energy-intensive businesses are constantly searching out tools to help control the magnitude of their bills.  One such tool, that goes by many names, is demand response (other names include interruptible capabilities, load shedding, and active load management).

Demand response represents the ability of a business to actively reduce the amount of electricity the business draws from the electric grid at specific times.  This typically occurs through the use of an on-site backup generator, shutting down or scaling back an energy-intensive business practice, or rescheduling an energy-intensive business practice to an off-peak time, typically the morning or evening.  Businesses with demand response capabilities can capitalize on those capabilities by avoiding certain costs and receiving compensation from both state and federal programs.

One significant challenge to the ability of businesses with demand response capabilities was recently resolved in favor of businesses. In February 2016, the United States Supreme Court, in F.E.R.C. v. Electric Power Supply Association (EPSA), upheld rules that provided compensation to businesses for committing their demand response capabilities to a regional grid operator.

Still, vital questions remain unresolved by the Supreme Court’s EPSA decision.  First, will states block businesses from participating in the federal programs? As things currently stand, the Federal Energy Regulatory Commission (FERC) has authorized states to block businesses in their states from participating in the federal programs.  Having lost their fight in the federal courts, electricity generators may turn to the states in an effort to block businesses from participating in the wholesale markets regulated by FERC.

Second, will FERC and the regional grid operators continue to rely on demand response resources?  While the Supreme Court has upheld FERC’s authority over demand response, PJM Interconnection (PJM), which is a regional transmission organization that serves 13 states, including Ohio, Pennsylvania and the District of Columbia, and other regional grid operators have taken and are taking actions to limit the scope of available federal demand response programs.

Third, how much compensation can demand response participants expect? Currently, demand response resources are generally paid the same amount as generators.  And we are talking big money:  PJM paid over $800 million to demand response resources in 2015 (these payments included all types of demand response in PJM, not just the specific demand response program at issue in EPSA).  As the ink was still drying on the Supreme Court’s decision in EPSA, FERC Commissioner Tony Clark encouraged the conversation to turn to whether the compensation that businesses receive for their demand response capabilities should be reduced.  So the question endures:  will customers continue to receive the same compensation as generators?

Getting help with energy costs

While the Supreme Court decision in EPSA is certainly good news for businesses, it is likely not the last word on the issue, and staying abreast of the varying state and federal electricity rates and programs applicable to businesses with demand response capabilities can be a daunting task.  McNees Wallace and Nurick’s Energy and Environmental Law Group frequently works with large energy consumers, state and federal regulators, and others in this dynamic area.

Matthew R. Pritchard practices in the Energy and Environmental Law Practice Group in the Columbus, Ohio office of McNees Wallace & Nurick LLC.  Joseph G. Bowser, a technical specialist in the Energy and Environmental Law Practice Group, assists clients of the firm with their participation in demand response programs. They can be reached at 614.469.8000 or mpritchard@mcneeslaw.com or jbowser@mcneeslaw.com